Method of extracting hydrocarbons

ABSTRACT

A mixture of liquefied carbon dioxide (above about 20 percent) and methanol (less than about 80 percent) is injected into an oil and gas well to fracture the oil bearing formation at suitable pressures. In a second and other following stages, a proppant mixed with a polymer is injected to prop open the fracture. Thereafter the oil and gas is again extracted.

RELATED APPLICATION

This application claims priority to and is a continuation-in-part of U.S. Provisional Patent Application 60/750,265 filed Dec. 14, 2005. The complete disclosure of this related application is hereby incorporated by reference for all purposes.

BACKGROUND OF THE INVENTION

Field: This invention relates to methods of extracting hydrocarbons (e.g., oil and gas) from a well by fracturing the underground formation, and more particularly to methods of enhancing the extraction of hydrocarbons by inserting a liquefied gas and solvent mixture as the fracturing fluid to effect the fracture without contaminating the underground structure.

The Relevant Technology: To enhance the extraction of available hydrocarbons such as oil and gas from a well, fracturing the underground formation has been an accepted practice to create pathways for the hydrocarbons to more easily migrate toward the bore. Fracturing may be accomplished by use of an explosive, by use of a gas generator which is some times called a gas gun, and hydraulically.

Hydraulic fracturing or “fracing” generally involves pumping a fluid into a well through the bore at a high enough pressure and at a high enough rate to overcome leak-off of the fluid into the formation. When the pressure of the fluid being injected reaches the parting pressure of stratas in the formation, the formation will fracture. While the precise nature of the fracture will vary based on the nature of the formation, the pressures reached, and other variables, it is generally believed that the fracture has a vertically oriented primary axis and is sometimes likened to a thin wing-like structure so that the fracture may be referred to as a bi-wing fracture because it has two such wings generally opposite each other extending away from the bore.

Once a fracture is induced, it is believed that the fracture will continue to propagate or extend so long as the fracturing fluid continues to be injected at a rate that exceeds the leak-off rate. That is, the formation is obviously porous so that the fracturing fluid can migrate away from the injection site at a rate (leak-off rate) that will increase as the fracture size increases allowing the fracturing fluid to be presented to an ever increasing volume/surface area. Of course, if the pumping is stopped, the injected fluid will continue to leak off into the formation, eventually allowing the induced fracture to close.

In order to prevent the induced fracture from closing as the fracturing fluid dissipates into the formation, and keep the fracture pathway open for migration of hydrocarbons (e.g., oil and gas) toward the bore, a propping agent also known as a proppant is inserted into the facture to keep the fracture from closing. Proppants are typically small hard particles that can be suspended in an injecting medium and injected into the well. The proppants are quite small and come in sizes that vary from around 50 mesh to perhaps as much as 1000 mesh. The small particles are hard and thus are difficult to crush. In turn when injected into a well and forced to migrate into the cracks formed in the strata in a fracture, they prevent the strata from coming together and in turn prevent at least some portions of the fracture from closing. In effect, proppants “prop” the fracture open. Known proppants include grains of sand and manufactured aluminum oxide particles. Of course there are many other types and kinds. The proppants are generally heavier than water and will sink when mixed into a low viscosity fracturing fluid such as water.

To be effective, the proppants need to be distributed throughout the fracture in the formation. Water and fracturing fluids of similar density or viscosity are not very effective in transporting the proppant throughout the entire fracture. Additives can be mixed into the low viscosity fracturing fluid to increase the viscosity and increase the ability of the mixture of fracturing fluid and the additive to retain the proppant in suspension as it moves toward the outer reaches of the fracture. Such additives include long chain polymers and materials such as guar. Cross linking of the chain can increase the viscosity and the transport properties of the mixture. See U.S. Pat. No. 7,036,597 (O'Brien, et al.) in which an alkaline crosslinked fluid is used as a second fluid in an hydraulic fracturing process.

While the additives help with the transportation of the proppant, they are also believed to lodge as residue in the pores of the porous formation. In turn, the oil and gas migration may not be enhanced as much as is desired or as much as is possible.

To reduce the clogging effect of the additives, a chemical breaker may be added after the proppant is injected with the higher viscosity mixture to break up the cross-linked bond and/or long hydrocarbon chains of the additives and to, in turn, allow the broken-up polymers to flow back to the bore and make way for the movement of the desired hydrocarbons toward the bore. See U.S. Pat. No. 7,036,597 (O'Brien, et al.).

Liquefied gas such as carbon dioxide (CO₂) and non liquefied gas like nitrogen (N₂) may be separately or jointly mixed with the fracing fluid to control the viscosity of the fracturing fluid and reduce the clogging effects of the additives.

Inasmuch as water is widely used as a fracturing fluid and also as a base fluid, efforts have been made to substitute methanol and add the CO₂ along with polymer gels to enhance fracing and reduce water damage. That is, the water can mix with clays and other materials in the formation to again inhibit the movement of the hydrocarbons. However, such mixtures have been unsuccessful because they are not good for transporting the proppant. Further, higher viscosity fracturing fluids are believed to create a shorter and wider fracture limiting to some extent the viability of the fracturing process.

To avoid the higher cost of higher viscosity fracing fluids, water has continued to be used in many processes particularly in formations that have a lower permeability. Of course, as stated, water does not transport proppant very well. In turn, the induced fracture may close resulting in a smaller effective fracture than desired.

Hybrid water fractures or “fracs” are now known. That is, fluids are injected in stages. First water or other low viscosity fluid is pumped into the well to create the fracture. A second stage follows in which gel is used to distribute proppants.

Both water fracs and hybrid water fracs are not producing the desired increased movement of hydrocarbons toward the bore, particularly for the formations which have a low or lower permeability. In the low permeability formations, it is believed that the water acts as a block by filling all the pores and inhibiting the migration of the hydrocarbons. In higher permeable formations, the adverse consequences of water and the clogging effect of the fluid to transport the proppant leads to disappointing results. In other circumstances, the water can mix with the clays and other materials leading to additional blockage.

A fracing process is needed to increase the promulgation of the fracture and to enhance the flow of hydrocarbons, but at the same time reducing the effect of water and not inhibiting the flow rate of hydrocarbons in the formation after fracture.

BRIEF SUMMARY OF THE INVENTION

A hydrocarbon well (e.g., an oil and/or gas well) is formed with a bore. The bore extends from the surface into a subterranean formation. The hydrocarbons are extracted from the well (production) using a variety of known methods. To enhance or extend production from the well, a new and novel method is used to fracture the subterranean formation to enhance the flow of hydrocarbons.

A reservoir means such as a tank is configured to retain a fracturing fluid. A fracturing fluid is formed by first obtaining a liquefied gas and a solvent, and mixing them to form the fracturing fluid. The fracturing fluid is positioned in the reservoir.

Conduit means extends from the reservoir to the bore to communicate the fracturing fluid from the reservoir to the bore. Injecting means is provided for injecting the fracturing fluid through the conduit and into the bore. Thereafter the injecting means is operated to inject the fracturing fluid into the bore at a pressure and in a volume sufficient to induce a fracture in the subterranean formation.

In a preferred method, a polymer is provided along with a proppant. The polymer is then mixed with the proppant and the resulting mixture is then positioned in the reservoir means. After the fracturing fluid has been injected in sufficiently to induce a desired fracture, the injecting means is then operated to inject the polymer-proppant mixture through the conduit means and into the bore at a pressure and in a volume sufficient to transport the polymer-proppant mixture into the fracture.

In a more preferred method, the injecting means is a well-head pump and may even be a piston type positive displacement pump. In a highly preferred method, the liquefied gas is carbon dioxide. In a more preferred method the solvent is methanol. In a more highly preferred method, the fracturing fluid is comprised of from about 20 percent methanol to about 80 percent methanol with the other material being liquid carbon dioxide.

BRIEF DESCRIPTION OF THE DRAWINGS

The following drawings depict only typical embodiments of the inventions and are therefore not to be considered limiting of its scope. The invention will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:

FIG. 1 depicts a drilled well with a fracture in cross section along the axis of the well bore;

FIG. 2 depicts a drilled well with a fracture in cross section transverse to the axis of the well bore; and

FIG. 3 is a block diagram of the steps followed in the fracturing method of the present invention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

In FIG. 1, a well 10 to recover hydrocarbons such as oil and gas is shown with a bore 12 shown extending down from the surface 11 into and through a pay zone 14. The bore 12 is formed using whatever drilling techniques are deemed to be most suitable to or for the formation as selected by the user. After drilling, the bore 12 is connected to well head equipment 16 that includes means to extract and send the desired hydrocarbons to suitable processing systems and equipment by suitable piping 18 as selected by the user.

The well head equipment 16 includes a pump 20 that is configured to assist in the extraction process by injecting materials into the well when desired by the user or operator of the well 10. The pump 20 may be any suitably powered or configured pump desired by the user, and is typically some form of positive displacement pump which is here specifically a piston pump that is driven by an engine such as a diesel engine which can be quite substantial. By way of example and not limitation, in some applications, engines capable of delivering in excess of about 3000 horsepower (hp) are used.

Referring to FIGS. 1-3, a fracturing procedure or process is used to fracture the underground formation 21 that can include strata 22. That is, it is known that hydrocarbon deposits such as oil and gas 24 are found in or between various subterranean strata 22. To extract the hydrocarbon material, it must migrate through the formation 21 toward the bore 12. Over time, the hydrocarbon material near 26 the bore 12 is depleted so that extraction is reduced and limited by the time for hydrocarbons to migrate toward and to the bore 12 from locations remote 28 from the bore 12. A fracture 30 is believed to provide a path of lesser resistance so that the flow of hydrocarbons 24 can be enhanced, and in turn allows for faster extraction and more complete extraction from the well 10 itself.

To effect the fracture 30 and improve migration of hydrocarbons 24 to the bore 12, a liquefied gas 32 is provided along with a suitable miscible fluid 34. The preferred liquefied gas 32 is carbon dioxide (CO₂) which has been formed into a liquid at a pressure of about 300 psi and at a temperature of about 0 degrees Fahrenheit. The carbon dioxide transforms into a gas after injection and thus helps drive water out of the surrounding pores and fracture. Thus, the risk of “water block” is reduced. Further, the carbon dioxide does not oxidize with the methanol, thus reducing the risk of fire above ground 11 and even after injection into the well 10.

Even though carbon dioxide is preferred, other gases that can be liquefied and combined/mixed with a miscible fluid may be used. A liquefied gas 32 is preferred because it can be mixed into a miscible fluid 34, and after injection into the well 10, should transform into a gas depending on pressure. Thus, the liquefied gas 32 has preferred liquid properties at the outset while preferably transforming after injection into a gas that can more easily migrate through pores in the strata and be extracted from the well 10 without inhibiting the flow of hydrocarbons 24 or blocking the pores in strata 22 of the underground formation 21.

The preferred miscible fluid 34 is methanol. Other miscible fluids may be used so long as they have a specific gravity and in turn viscosity comparable to methanol. Methanol is preferred because it is miscible with water (H₂O) and acts as a drying agent to remove residual water from the fracture and even from the surrounding formation. In other words, residual water that may be present naturally or from prior treatments or from later injection of proppants, can be reduced by the drying effect of the methanol. Removal of water is believed to allow enhanced flow of hydrocarbons toward the pay zone.

The miscible fluid 34 and the liquefied gas 32 are mixed 36 into a mixture 37, which is the fracturing fluid, and retained in a reservoir 38 for immediate or prompt pumping by the well head pump 20 from or through conduit 40 and into the bore 12. The mixture 37 is comprised of about 20 percent to about 80 percent solvent 34, the balance being the liquefied gas 32.

The mixture 37 is a fracturing fluid that is injected 42 into the well 10 and more particularly into the bore 12. The bore 12 is plugged 44 at an appropriate location to force the fracturing fluid or mixture 37 into the pay zone 14, and more specifically into the strata 22 of the formation 21 by the pump 20 at a suitable rate that exceeds the leak-off rate. As the mixture 37 enters the formation 21 under pressure, it will migrate into and through the pores of the strata 22. The rate of injection of the mixture 37 is controlled by the pump 20 which is operated to inject at a rate that exceeds the leak-off rate. Further, the pump 20 is operated to increase the pressure of the mixture 37 to a point that it will induce or cause the strata 22 of the formation 21 to separate or fracture. Pressures for this hydraulic fracturing process may range widely and can run from 2,000 to in excess of 13,000 pounds per square inch (psi).

The pressure of the mixture 37 includes the column pressure of the mixture 37. That is, a column of water that is 10 feet high has a weight and in turn exerts a pressure of 4.434 psi. Thus a 5000 foot deep 44 well that is injected with water would have a pressure in the pay zone 14 of about 2217 psi based on the column height 46 of the water. The mixture 37 is less viscous than water and has a columnar pressure of about 0.7 pounds per foot so that it would yield a columnar pressure for a 5000 foot deep well of about 3500 psi.

The pressure of the mixture 37 in the formation is thus the sum of the pressure due to the columnar height 46 plus the pressure added by the pump less pressure lost due to friction. While fracturing pressures will vary from well to well, it can be expected that pressures of the mixture 37 to induce the fracture 42 will be in the range of about 2,000 psi to about 20,000 psi with about 15,000 psi being the maximum (depending on well depth), because higher pressures may damage the pipe or tubing in the bore 12. The volume of fracing fluid or mixture 37 to effect a fracture 30 will vary widely based on the nature of the formation and the size of the producing zone. Small production zones may require only about 100 barrels of mixture 37 with large production zones demanding as much as 4 million gallons.

A tilt-meter (not shown) may be used to predict the crack propagation. After the fracture 30 is formed by injection of the mixture 37, a proppant is injected to keep the fracture from closing. A proppant 50 is provided and combined with a polymer 52 or mixed 54 to form a proppant mixture 56 which is retained by the reservoir means 38. The proppant mixture 56 is accessed by the pump by operation of selected stop valves 58 and 60. The proppant mixture 56 then moves to and through the pump 20 and into bore 12. The proppant mixture 56 is thereby injected 59 down the bore 12 and into the fracture 30 for dispersal into the fracture 30 and to the farther reaches 62 and 64 of the fracture 30. The proppant 50 may be any suitable commercial proppant which may have particles that vary in size from 1/20 to 1/40 of an inch in effective diameter (sometimes referred to as 20-40). Another known proppant is referred to as 10-30 and has particles that vary from 1/10 to 1/30 of an inch in effective diameter. In the present application, a wide range of commercial proppants may be used including a silica (sand) screened to select only those of about 0.01 inch effective diameter. Aluminum oxide (AlO₂) particles of similar size may also be used. The proppant 50 when transported into the fracture 30 by the polymer 52 will remain in the fracture as the polymer evolves to something near the viscosity of water leaving the proppant in place to hold the fracture 30 open and provide a pathway for hydrocarbons 24 to migrate toward the bore 12 for further extraction by the well.

It should be understood that the reservoir means 38 is shown here to be any kind or type of container that has in it either one or both of mixture 37 and mixture 56. In practice, the reservoir means 38 may be one or more or combinations of containers or devices (e.g., barrels, tanks, towers) which eventually supply the mixture 37 and/or the mixture 56 to the bore 12 through a pump like pump 20. The pump 20 may be any suitable well-head pump used to inject fluids and connected to extract fluids. Of course any other suitable pump configuration or arrangement may be used to extract materials such as fluids from the fracing and hydrocarbons.

The polymer 52 may be any of commonly used fracturing gel with a viscosity sufficient to suspend the proppant. It may be alcohol based or water based. At present, it appears to be preferable to use a water based material that has a physical appearance that is referred to as a gel and is much like prepared JELLO®. Such a polymer, including guar, breaks down over time. For example, a guar gel will break down into at least water and guar residue. Other residue may remain depending on the initial composition of the polymer.

After completion of the second stage, at least one more stage of injection may be followed. That is, a third, fourth, fifth or more stages may be followed in which more proppant and polymer is injected 62 in a fashion comparable to stage 2. That is, additional proppant 50 and polymer 52 is mixed to form a third mixture 64. The proppant may be of the same size or be of slightly different size. Inasmuch as it is believed that some of the proppant will crush, smaller proppants (less than 0.1 inches in effective diameter) may be used in the third stage and above. The size and concentration of the proppant is dictated by the size or width of the fracture created. For larger frac width, the proppant 50 for mixture 64 may be larger (e.g., 0.15 to 0.2 inches in effective diameter).

Of course after completion of the third or more stages, the bore 12 may be cleared by the well pressure itself or in some cases by pumping it out using the well-head pump or any other suitable pump. Extraction of hydrocarbons 24 is recommenced 66 from the pay zone 14 through the bore 12.

The present invention may be embodied in other specific forms without departing from its spirit or essential characteristics. The described embodiments are to be considered in all respects only as illustrative and not restrictive. The scope of the invention is, therefore, indicated by the appended claims rather than by the foregoing description. All changes which come within the meaning and range of equivalency of the claims are to be embraced within their scope. 

1. A method of fracturing a subterranean formation of a hydrocarbon well formed with a bore, said method comprising: providing reservoir means configured to retain a fracturing fluid therein; providing a liquefied gas; providing a solvent; mixing said liquefied gas and said solvent to form a fracturing fluid and positioning said fracturing fluid in said reservoir; providing conduit means to extend from said reservoir means to said bore; connecting said conduit means to communicate said fracturing fluid from said reservoir to said bore; providing injecting means for injecting said fracturing fluid through said conduit means and into said bore; and operating said injecting means to inject said fracturing fluid into said bore at a pressure and in a volume sufficient to induce a fracture in said subterranean formation.
 2. The method of claim 1 further including: providing a polymer; providing a proppant; mixing said proppant and said polymer and placing said polymer-proppant mixture in said reservoir means; operating said injecting means to inject said polymer proppant mixture through said conduit means and into said bore at a pressure and in a volume sufficient to transport said polymer-proppant mixture into said fracture.
 3. The method of claim 2 wherein said injecting means is a well head pump.
 4. The method of claim 2 wherein said liquefied gas is carbon dioxide.
 5. The method of claim 4 wherein said solvent is methanol.
 6. The method of claim 5 wherein said fracturing fluid is comprised of from about 20 percent methanol to about 80% methanol.
 7. The method of claim 1 further including operating said well head pump to extract water from said bore.
 8. A method of fracturing a subterranean formation of a hydrocarbon well formed with a bore, said method comprising: providing reservoir means configured to retain a fracturing fluid therein; providing conduit means to extend from said reservoir means to said bore; providing injecting means for injecting said fracturing fluid through said conduit means and into said bore; providing means for extracting fluids from said bore; providing a liquefied carbon dioxide; providing methanol; mixing said liquefied carbon dioxide gas and said methanol to form a fracturing fluid and positioning said fracturing fluid in said reservoir; connecting said conduit means to communicate said fracturing fluid from said reservoir to said bore; and operating said injecting means to inject said fracturing fluid into said bore at a pressure and in a volume sufficient to induce a fracture in said subterranean formation.
 9. The method of claim 8 further including: providing a polymer; providing a proppant; mixing said proppant and said polymer and placing said polymer-proppant mixture in said reservoir means; operating said injecting means to inject said polymer proppant mixture through said conduit means and into said bore at a pressure and in a volume sufficient to transport said polymer-proppant mixture into said fracture.
 10. The method of claim 9 further including providing pump means to extract material from said bore, connecting said pump means to said bore; and operating said pump means to extract material from said bore.
 11. A system for fracing an oil and gas well having a bore with a pay zone, said system comprising reservoir means configured to retain a fracturing fluid therein; a fracturing fluid positionable in said reservoir means, said fracturing fluid including liquefied carbon dioxide mixed with a solvent; conduit means connected to extend from said reservoir means to said bore to communicate said fracturing fluid from said reservoir to said bore; injecting means interconnected in said conduit means and operable to injecting said fracturing fluid through said conduit means into said bore and to said pay zone at a pressure and in a volume sufficient to induce a fracture in said subterranean formation proximate said pay zone. 